Total 4731 registered members

Compact design reduces volume by up to 33 percent and lowers environmental impact

ABB's latest generation 420 kV GIS (April 2012)

ABB's latest generation 420 kV GIS (April 2012)

Zurich, Switzerland, April 23, 2012 – ABB, the leading power and automation technology group, announced the launch of its new generation 420kV (kilovolt) Gas Insulated Switchgear (GIS) at the Hannover Fair being held in Germany from 23-27 April 2012. The new design reduces product volume by up to 33 per cent (width x depth x height) compared to its predecessor resulting in a considerably smaller footprint.

The compactness of the unit makes it ideally suited for installations where space is a constraint and also reduces the amount of SF6 insulating gas requirement by as much as 40 percent making it more environmentally friendly. It is also designed to enhance resource efficiency by reducing thermal losses, lowering transportation costs and optimizing investment in infrastructure.

The new GIS can be factory assembled, tested, and shipped as one bay in a container instead of multiple assembly units, saving site installation and commissioning time by up to 40 percent compared with traditional designs. Frontal access to drives, position indicators and service platforms enable easier operation, inspection and maintenance. Standardized modules and connection elements also enable flexibility in terms of configurations and building optimization.

The product features a fast single-interrupter dual motion circuit breaker and has been designed for current ratings up to 5000A (amperes). It is capable of providing protection to power networks with rated short-circuit currents up to 63kA (kilo amperes).

“A compact and more user friendly design, faster on-site commissioning and lower environmental impact are some of the key features of this latest generation of Gas Insulated Switchgear”, said Giandomenico Rivetti, head of ABB’s High Voltage Products business, a part of the company’s Power Products division. “The introduction of this 420kV GIS is part of ABB’s ongoing technology and innovation focus and follows the recent launch of our advanced 245kV and 72.5kV versions.”

In a power system, switchgear is used to control, protect and isolate electrical equipment thereby enhancing the reliability of electrical supply. With GIS technology, key components including contacts and conductors are protected with insulating gas. Compactness, reliability and robustness make this a preferred solution where space is a constraint (e.g. busy cities) or in harsh environmental conditions.

ABB pioneered high-voltage GIS in the mid-1960s and continues to drive technology and innovation, offering a full range product portfolio with voltage levels from 72.5kV to 1,100kV. As a market leader in high-voltage GIS technology, ABB has a global installed base of more than 20,000 bays.

ABB ( is a leader in power and automation technologies that enable utility and industry customers to improve their performance while lowering environmental impact. The ABB Group of companies operates in around 100 countries and employs about 135,000 people.


Related articles

Standard IEC 60947-2

Standard IEC 60947-2 | Circuit Breakers

This standard applies to circuit-breakers, the main contacts of which are intended to be connected to circuits, the rated voltage of which does not exceed 1000 VAC or 1500 VDC.; it also contains additional requirements for integrally fused circuit-breakers.

It applies whatever the rated currents, the method of construction or the proposed applications of the circuit-breakers may be.

Changes in dependability needs and technologies have led to a marked increase in standard requirements for industrial circuit-breakers.

Conformity with standard IEC 947-2, renamed IEC 60947-2 in 1997, can be considered as an ‘all-risk’ insurance for use of circuit-breakers. This standard has been approved by all countries.

The principles

Standard IEC 60947-2 is part of a series of standards defining the specifications for LV electrical switchgear:

  • the general rules IEC 60947-1, that group the definitions, specifications and tests common to all LV industrial switchgear.
  • the product standards IEC 60947-2 to 7, that deal with specifications and tests specific to the product concerned. Standard IEC 60947-2 applies to circuit-breakers and their associated trip units. Circuit-breaker operating data depend on the trip units or relays that control their opening in specific conditions.

This standard defines the main data of industrial circuit-breakers:

  • their classification: utilisation category, suitability for isolation, etc.
  • the electrical setting data
  • the information useful for operation
  • the design measures
  • coordination of protection devices

The standard also draws up series of conformity tests to be undergone by the circuitbreakers. These tests, which are very complete, are very close to real operating conditions. Conformity of these tests with standard IEC 60947-2 is verified by accredited laboratories.

Table of main data (appendix K IEC 60947-2):

Table of main data (appendix K IEC 60947-2)

Circuit-breaker category

Category IEC 60947-2 defines two circuit-breaker categories:

  • category A circuit-breakers, for which no tripping delay is provided. This is normally the case of moulded case circuit-breakers. These circuit-breakers can provide current discrimination.
  • category B circuit-breakers, for which, in order to provide time discrimination, tripping can be delayed (up to 1 s) for all short-circuits of value less than the current Icw.

This is normally the case of power or moulded case circuit-breakers with high ratings. For circuit-breakers installed in the MSBs, it is important to have an lcw equal to lcu in order to naturally provide discrimination up to full ultimate breaking capacity Icu.

Reminders of standard-related electrical data

The setting data are given by the tripping curves. These curves contain some areas limited by the following currents.

The setting data are given by the tripping curves.

  • Rated operational current (In)
    In (in A rms) = maximum uninterrupted current withstood at a given ambient temperature without abnormal temperature rise.
    E.g. 125 A at 40 °C
  • Adjustable overload setting current (lr)
    Ir (in A rms) is a function of ln. lr characterises overload protection. For operation in overload, the conventional non-tripping currents lnd and tripping currents ld are:

    • Ind = 1.05 Ir
    • Id = 1.30 Ir

    Id is given for a conventional tripping time. For a current greater than ld, tripping by thermal effect will take place according to an inverse time curve. Ir is known as Long Time Protection (LTP).

  • Short time tripping setting current (Isd)
    (in kA rms) is a function of Ir. lsd characterises short-circuit protection. The circuit breaker opens according to the short time tripping curve:

    • either with a time delay tsd,
    • or with constant I2t,
    • or instantaneously (similar to instantaneous protection).

    Isd is known as Short Time Protection or lm.

  • Instantaneous tripping setting current (Ii)
    Ii (in kA) is given as a function of ln. It characterises the instantaneous short-circuit protection for all circuit-breaker categories. For high overcurrents (short-circuits) greater than the li threshold, the circuit-breaker must immediately break the fault current.
    This protection device can be disabled according to the technology and type of circuit-breaker (particularly B category circuit-breakers).

Rated short time withstand current

Table for calculation of asymmetrical short-circuits (IEC 60947.2 para.

Table for calculation of asymmetrical short-circuits

  • Rated short-circuit making capacity(*) (Icm)
    Icm (peak kA) is the maximum value of the asymmetrical short-circuit current that the circuit-breaker can make and break. For a circuit-breaker, the stress to be managed is greatest on closing on a short-circuit.
  • Rated ultimate breaking capacity(*) (Icu)
    Icu (kA rms) is the maximum short-circuit current value that the circuit-breaker can break. It is verified according to a sequence of standardised tests. After this sequence, the circuit-breaker must not be dangerous. This characteristic is defined for a specific voltage rating Ue.
  • Rated service breaking capacity(*) (Ics)
    Ics (kA rms) is given by the manufacturer and is expressed as a % of Icu. This performance is very important as it gives the ability of a circuit-breaker to provide totally normal operation once it has broken this short-circuit current three times. The higher Ics, the more effective the circuit-breaker.
  • Rated short time withstand current(*) (Icw)
    Defined for B category circuit-breakers
    Icw (kA rms) is the maximum short-circuit current that the circuit-breaker can withstand for a short period of time (0.05 to 1 s) without its properties being affected. This performance is verified during the standardised test sequence.
    (*) These data are defined for a specific voltage rating Ue.
Circuit-breaker coordination

The term coordination concerns the behaviour of two devices placed in series in electrical power distribution in the presence of a short-circuit.

Cascading and discrimination

  • Cascading or back-up protection
    This consists of installing an upstream circuit-breaker D1 to help a downstream circuit-breaker D2 to break short-circuit currents greater than its ultimate breaking capacity IcuD2. This value is marked IcuD2+D1.
    IEC 60947-2 recognises cascading between two circuit-breakers. For critical points, where tripping curves overlap, cascading must be verified by tests.
  • Discrimination
    This consists of providing coordination between the operating characteristics of circuit-breakers placed in series so that should a downstream fault occur, only the circuit-breaker placed immediately upstream of the fault will trip.
    IEC 60947-2 defines a current value ls known as the discrimination limit such that:

    • if the fault current is less than this value ls, only the downstream circuit-breaker D2 trips,
    • if the fault current is greater than this value ls, both circuit-breakers D1 and D2 trip.

    Just as for cascading, discrimination must be verified by tests for critical points.

Discrimination and cascading can only be guaranteed by the manufacturer who will record his tests in tables.

IEC 60947-2 Summary

Standard IEC 60947.2 specifies the main data of Industrial Circuit-Breakers:

  • the utilisation category
  • the setting data
  • the design measures
  • etc.

It draws up a series of very complete tests representative of circuit-breaker real operating conditions.

SOURCE: Schneider Electric


Related articles

AKD-20 low-voltage switchgear continues the tradition of the AKD switchgear line while delivering enhanced arc flash protection. Built to ANSI standards, its protection features include non-vented panels plus insulated and isolated bus, and it integrates our new state-of-the-art EntelliGuard® breaker-trip unit system. It also features an optimized footprint so that it now fits into a smaller area for the most common configurations.

EntelliGuard® G circuit breakers are the newest line of GE low-voltage circuit breakers, the next step in the evolution of a line known for its exceptional designs and performance. They are available from 800A to 5000A, with fault interruption ratings up to 150kAIC – without fuses.

Integral to the EntelliGuard G line are the new, state-of-the-art EntelliGuard TU Trip Units, which provide superior system protection, system reliability, monitoring and communications. The breaker-trip unit system delivers superior circuit protection without compromising either selectivity or arc flash protection. The EntelliGuard breaker-trip unit system demonstrates yet again GE’s core competencies in reliable electric power distribution, circuit protection and personnel protection. AKD-20 includes many features that address the needs of system reliability, arc flash protection and reduced footprint size.

Features and Benefits

  • The optimized footprint uses smaller section sizes when possible. Sections are provided in 22″, 30″ or 38″ widths.
  • Breaker compartment doors have no ventilation openings, thus protecting operators from hot ionized gases vented by the breaker during circuit interruption.
  • A superior bus system offers different levels of protection.  Insulated and isolated bus makes maintenance procedures touch friendly to reduce the risk of arc flash.
  • True closed-door drawout construction is standard with all AKD-20 equipment. The breaker compartment doors remain stationary and closed while the breaker is racked out from the connect position, through test, to the disconnect position. Doors are secured with rugged 1/4-turn latches.
  • An easy-to-read metal instrument panel above each circuit breaker holds a variety of control circuit devices, including the RELT switch.
  • Each circuit breaker is located in a completely enclosed ventilated compartment with grounded steel barriers to minimize the possibility of fault communication between compartments.
  • Optional safety shutters protect operators from accidental contact with live conductors when the breaker is withdrawn.
  • Easy access to equipment compartments simplifies maintenance of the breaker cubicle and control circuit elements as well as inspection of the bolted bus connections.
  • The conduit entrance area meets NEC requirements.  Extended depth frame options are available in 7″ and 14“ sizes for applications requiring additional cable space. The section width also can be increased for additional cable space.
  • A rail-mounted hoist on top of the switchgear provides the means for installing and removing breakers from the equipment. This is a standard feature on NEMA 3R outdoor walk-in construction and optional on indoor construction.
  • Control wires run between compartments in steel riser channels. Customer terminal blocks are located in metal-enclosed wire troughs in the rear cable area. Intercubicle wiring is run in a wireway on top of the switchgear, where interconnection terminal blocks are located.
  • All EntelliGuard G circuit breakers are equipped with rollers and a guidebar to provide easy and accurate drawout operation.
  • An optional remote racking device reduces the risk of the arc flash hazard by allowing the operator or electrician to move the breaker anywhere between the DISCONNECT and CONNECT positions from outside the arc flash boundary.
  • Optional infrared (IR) scanning windows can be installed in the switchgear rear covers to facilitate the use of IR cameras for thermally scanning cable terminations.
  • AKD-20 switchgear can be expanded easily to handle increased loading and system changes. Specify a requirement for a fully equipped future breaker to obtain a cubicle that has been set up for additional breaker installation, or add vertical sections without modifications or the use of transition sections.
  • An array of safety interlock and padlocking features are available to accommodate any type of lockout-tagout procedure a customer may have.
  • Optional Power Management:  With the proper devices and GE Enervista Power Management Control System (PMCS), facility power can be tracked and controlled.
  • Optional Metering and Power Quality:  The latest high technology EPM devices are available for the AKD-20 with broad capabilities for usage monitoring, cost allocation, load monitoring, demand tracking, common couplings with utilities, load and process control, and power quality monitoring.


Related articles

Maintenance Of SF6 Gas Circuit Breakers

Maintenance Of SF6 Gas Circuit Breakers

Sulfur Hexafluoride (SF6) is an excellent gaseous dielectric for high voltage power applications. It has been used extensively in high voltage circuit breakers and other switchgears employed by the power industry.

Applications for SF6 include gas insulated transmission lines and’gas insulated power distributions. The combined electrical, physical, chemical and thermal properties offer many advantages when used in power switchgears.

Some of the outstanding properties of SF6 making it desirable to use in power applications are:

  • High dielectric strength
  • Unique arc-quenching ability
  • Excellent thermal stability
  • Good thermal conductivity

Properties Of SF6 (Sulfur Hexafuoride) Gas

  • Toxicity – SF6 is odorless, colorless, tasteless, and nontoxic in its pure state. It can, however, exclude oxy­gen and cause suffocation. If the normal oxygen content of air is re­duced from 21 percent to less than 13 percent, suffocation can occur without warning. Therefore, circuit breaker tanks should be purged out after opening.
  • Toxicity of arc products – Toxic decomposition products are formed when SF6 gas is subjected to an elec­tric arc. The decomposition products are metal fluorides and form a white or tan powder. Toxic gases are also formed which have the characteristic odor of rotten eggs. Do not breathe the vapors remaining in a circuit breaker where arcing or corona dis­charges have occurred in the gas. Evacuate the faulted SF6 gas from the circuit breaker and flush with fresh air before working on the circuit breaker.
  • Physical properties – SF6 is one of the heaviest known gases with a den­sity about five times the density of air under similar conditions. SF6 shows little change in vapor pressure over a wide temperature range and is a soft gas in that it is more compressible dynamically than air. The heat trans­fer coefficient of SF6 is greater than air and its cooling characteristics by convection are about 1.6 times air.
  • Dielectric strength – SF6 has a di­electric strength about three times that of air at one atmosphere pressure for a given electrode spacing. The dielectric strength increases with increasing pressure; and at three atmospheres, the dielectric strength is roughly equivalent to transformer oil. The heaters for SF6 in circuit breakers are required to keep the gas from liquefying because, as the gas liquifies, the pressure drops, lowering the dielectric strength. The exact dielectric strength, as compared to air, varies with electrical configuration, electrode spacing, and electrode configuration.
  • Arc quenching – SF6 is approxi­mately 100 times more effective than air in quenching spurious arcing. SF6 also has a high thermal heat capacity that can absorb the energy of the arc without much of a temperature rise.
  • Electrical arc breakdown – Because of the arc-quenching ability of SF6, corona and arcing in SF6 does not occur until way past the voltage level of onset of corona and arcing in air. SF6 will slowly decompose when ex­posed to continuous corona.

All SF6 breakdown or arc products are toxic. Normal circuit breaker operation produces small quantities of arc products during current interruption which normally recombine to SF6. Arc products which do not recombine, or which combine with any oxygen or moisture present, are normally re­moved by the molecular sieve filter material within the circuit breaker.

Handling Nonfaulted SF6

The procedures for handling nonfaulted SF6 are well covered in manufacturer’s instruction books. These procedures normally consist of removing the SF6 from the circuit breaker, filtering and storing it in a gas cart as a liquid, and transferring it back to the circuit breaker after the circuit breaker maintenance has been performed. No special dress or precautions are required when handling nonfaulted SF6.

Handling Faulted SF6


  • Faulted SF6 gas – Faulted SF6 gas smells like rotten eggs and can cause nausea and minor irritation of the eyes and upper respiratory tract. Normally, faulted SF6 gas is so foul smelling no one can stand exposure long enough at a concentration high enough to cause permanent damage.
  • Solid arc products - Solid arc products are toxic and are a white or off-white, ashlike powder. Contact with the skin may cause an irritation or possible painful fluoride burn. If solid arc products come in contact with the skin, wash immediately with a large amount of water. If water is not available, vacuum off arc products with a vacuum cleaner.

Clothing and safety equipment requirements

When handling and re­ moving solid arc products from faulted SF6, the following clothing and safety equipment should be worn:

  • Coveralls – Coveralls must be worn when removing solid arc products. Coveralls are not required after all solid arc products are cleaned up. Disposable coveralls are recommended for use when removing solid arc products; however, regular coveralls can be worn if disposable ones are not available, provided they are washed at the end of each day.
  • Hoods – Hoods must be worn when removing solid arc products from inside a faulted dead-tank circuit breaker.
  • Gloves – Gloves must be worn when solid arc products are hah-died. Inexpensive, disposable gloves are recommended. Non-disposable gloves must be washed in water and allowed to drip-dry after use.
  • Boots – Slip-on boots, non-disposable or plastic disposable, must be worn by employees who enter eternally faulted dead-tank circuit breakers. Slip-on boots are not required after the removal of solid arc products and vacuuming. Nondisposable boots must be washed in water and dried after use.
  • Safety glasses – Safety glasses are recommended when handling solid arc products if a full face respirator is not worn.
  • Respirator – A cartridge, dust-type respirator is required when entering an internally faulted dead-tank circuit breaker. The respirator will remove solid arc products from air breathed, but it does not supply oxygen so it must only be used when there is sufficient oxygen to support life. The filter and cartridge should be changed when an odor is sensed through the respirator. The use of respirators is optional for work on circuit breakers whose in­ terrupter units are not large enough for a man to enter and the units are well ventilated.
    Air-line-type respirators should be used when the cartridge type is ineffective due to providing too short a work time before the cartridge becomes contaminated and an odor is sensed.
    When an air-line respirator is used, a minimum of two working respirators must be available on the job before any employee is allowed to enter the circuit breaker tank.

Disposal of waste

All materials used in the cleanup operation for large quantities of SF6 arc products shall be placed in a 55­ gal drum and disposed of as hazardous waste.

The following items should be disposed of:

  • All solid arc products
  • All disposable protective clothing
  • All cleaning rags
  • Filters from respirators
  • Molecular sieve from breaker and gas cart
  • Vacuum filter element


Related articles

Siemens technical publication | Loss Of Vacuum

Siemens technical publication | Loss Of Vacuum

If a vacuum interrupter should lose vacuum, several operating situations should be considered:

1. With contacts open
2. When closing
3. When closed and operating normally
4. When opening and interrupting normal current
5. When opening and interrupting a fault.

Cases 1, 2 and 3 are relatively straightforward. Generally, the system sees no impact from loss of vacuum in such a situation. Cases 4 and 5, however, require further discussion. Suppose there is a feeder circuit breaker with a vacuum interrupter on phase 3 that has lost vacuum. If the load being served by the failed interrupter is a deltaconnected (ungrounded) load, a switching operation would not result in a failure. Essentially, nothing would happen. The two good phases (phase 1 and phase 2, in this example) would be able to clear the circuit, and current in the failed interrupter (phase 3) would cease.

The alternative case of a grounded load is a different situation. In this case, interruption in the two good phases (phase 1 and phase 2) would not cause current to stop flowing in phase 3, and the arc would continue to exist in phase 3. With nothing to stop it, this current would continue until some backup protection operated. The result, of course, would be destruction of the interrupter.

Since the predominant usage of circuit breakers in the 5-15 kV range is on grounded circuits, we investigated the impact of a failed interrupter some years ago in the test lab. We intentionally caused an interrupter to lose vacuum by opening the tube to the atmosphere. We then subjected the circuit breaker to a full short circuit interruption. As predicted,
the “flat” interrupter did not successfully clear the affected phase, and the “flat” interrupter was destroyed. The laboratory backup breaker cleared the fault. Following the test, the circuit breaker was removed from the switchgear cell. It was very sooty, but mechanically intact. The soot was cleaned from the circuit breaker and the switchgear cell, the faulty interrupter was replaced, and the circuit breaker was re-inserted in the cell. Further short circuit interruption tests were conducted the same day on the circuit breaker.

Field experience in the years since that test was conducted supports the information gained in the laboratory experiment. One of our customers, a large chemical operation, encountered separate failures (one with an air magnetic circuit breaker and one with a vacuum circuit breaker) on a particular circuit configuration. Two different installations, in different countries, were involved. They shared a common circuit configuration and failure mode. The circuit configuration, a tie circuit in which the sources on each side of the circuit
breaker were not in synchronism, imposed approximately double rated voltage across the contact gap, which caused the circuit breaker to fail. Since these failures resulted from application in violation of the guidelines of the ANSI standards, and greatly in excess of the design ratings of the circuit breakers, they are not indicative of a design
problem with the equipment.

However, the damage that resulted from the failures is of interest. In the case of the air magnetic circuit breaker, the unit housing the failed circuit breaker was destroyed, and the adjacent switchgear units on either side were damaged extensively, requiring significant rebuilding. The air magnetic circuit breaker was a total loss. In the case of the vacuum circuit breaker, the failure was considerably less violent. The vacuum interrupters were replaced, and the arc by-products (soot) cleaned from both the circuit breaker and the compartment. The unit was put back into service. Our test experience in the laboratory, where we routinely explore the limits of interrupter performance, also supports these results.

More recently, several tests were performed in our high-power test laboratory to compare the results of attempted interruptions with “leaky” vacuum interrupters. A small hole (approximately 1/8” diameter) was drilled in the interrupter housing, to simulate a vacuum interrupter that had lost vacuum.

The results of these tests were very interesting:

  1. One pole of a vacuum circuit breaker was subjected to an attempted interruption of 1310 A (rated continuous current = 1250 A). The current was allowed to flow in the “failed” interrupter for 2.06 seconds, at which point the laboratory breaker interrupted. No parts of the “failed” circuit breaker or the interrupter flew off, nor did the circuit breaker explode. The paint on the exterior of the interrupter arcing chamber peeled off. The remainder of the circuit breaker was undamaged.
  2. A second pole of the same vacuum circuit breaker was subjected to an attempted interruption of 25 kA (rated interrupting current = 25 kA), for an arc-duration of 0.60 seconds, with the laboratory breaker interrupting the current at that time. The arc burned a hole in the side of the arc chamber. The circuit breaker did not explode, nor did parts of the circuit breaker fly off. Glowing particles were ejected from the hole in the arcing chamber. None of the mechanical components or other interrupters were damaged. Essentially, all damage was confined to the failed interrupter.

Our experience suggests rather strongly that the effects of a vacuum interrupter failure on the equipment are very minor, compared to the impact of failures with alternative interruption technologies. But the real question is not what the results of a failure might be, but rather, what is the likelihood of a failure? The failure rate of Siemens vacuum interrupters is so low that loss of vacuum is no longer a significant concern. In the early 1960s with early vacuum interrupters, it was a big problem. A vacuum interrupter is constructed with all connections between dissimilar materials made by brazing or welding. No organic materials are used. In the early years, many hand-production techniques were used, especially when borosilicate glass was used for the insulating envelope, as it could not tolerate high temperatures. Today, machine welding and batch induction furnace brazing are employed with extremely tight process control. The only moving part inside the interrupter is the copper contact, which is connected to the interrupter end plate with a welded stainless steel bellows. Since the bellows is welded to both the contact and the interrupter end plate, the failure rate of this moving connection is extremely low. This accounts for the
extremely high reliability of Siemens vacuum interrupters today.

In fact, the MTTF (mean time to failure) of Siemens power vacuum interrupters has now reached 24,000 years (as of October 1991). Questions raised by customers regarding loss of vacuum were legitimate concerns in the 1960s, when the use of vacuum interrupters for power applications was in its infancy. At that time, vacuum interrupters suffered from frequent leaks, and surges were a problem. There was only one firm that offered vacuum circuit breakers then, and reports suggest that they had many problems. We entered the vacuum circuit breaker market in 1974, using Allis-Chalmers’ technology and copper-bismuth contact materials. In the early 1980′s, after becoming part of the worldwide Siemens organization, we were able to convert our vacuum designs to use Siemens vacuum interrupters, which had been introduced in Europe in the mid-1970s. Thus, when we adopted the Siemens vacuum interrupters in the U.S., they already had a very well established field performance record.

The principle conceptual differences in the modern Siemens vacuum interrupters from the early 1960s designs lies in contact material and process control. Surge phenomena are more difficult to deal with when copper-bismuth contacts are used than with today’s chromecopper contacts. Similarly, leaks were harder to control with vacuum interrupters built largely by hand than with today’s units. Today, great attention is paid to process control and elimination of the human factor (variability) in manufacture. The result is that the Siemens vacuum interrupters today can be expected to have a long service life and to impose dielectric stress on load equipment that is not significantly different from the stresses associated with traditional air magnetic or oil circuit breakers.


Published by: SIEMENS AG


Related articles

Maintenance Of High Voltage Circuit Breakers

Maintenance Of High Voltage Circuit Breakers

Most manufacturers recommend com­plete inspections, external and internal, at intervals of from 6 to 12 months.

Ex­perience has shown that a considerable expense is involved, some of which may be unnecessary, in adhering to the manufacturer’s recommendations of in­ ternal inspections at 6 to 12 month intervals. With proper external checks, part of the expense, delay, and labor of internal inspections may be avoided without sacrifice of dependability.

Inspection schedule for new breakers

A temporary schedule of frequent inspections is necessary after the erection of new equipment, the modification or modernization of old equipment, or the replication of old equipment under different condi­ tions.

The temporary schedule is required to Correct internal defects which ordinarily appear in the first year of service and to correlate external check procedures with internal conditions as a basis for more conservative maintenance program thereafter. Assuming that a circuit breaker shows no serious defects at the early complete inspections and no heavy interrupting duty is imposed, the following inspection schedule is recommended:

.6 months after erection.Complete inspection and adjustment
.12 months after .previous inspection.Complete inspection and adjustment
.12 months after .previous inspection.Complete inspection and adjustment
.12 months after .previous inspection.External checks and inspection; if checks are .satisfactory, no internal inspection
.12 months after .previous inspection.Complete inspection and adjustment


Inspection schedule for existing breakers

The inspection schedule should be based by the interrupting duty imposed on the breaker. It is advisable to make a complete internal inspection after the first severe fault interruption. If internal conditions are satisfactory, progressively more fault interruptions may be allowed before an internal inspection is made. Average experience indicates that up to five fault interruptions are allowable between inspections on 230 kV and above circuit breakers, and up to 10 fault interruptions are allowable on circuit breakers rated under 230 kV.

Normally, no more than 2 years should elapse between external in­ spections or 4 years between internal inspections.

External Inspection Guide

The following items should be included in an external inspection of a high-voltage breaker.

  1. Visually inspect PCB externals and operating mechanism. The tripping latches should be examined with spe­ cial care since small errors in adjustments and clearances and roughness of the latching surfaces may cause the breaker to fail to latch properly or increase the force neces­ sary to trip the breaker to such an extent that electrical tripping will not always be successful, especially if the tripping voltage is low. Excessive “opening” spring pressure can cause excessive friction at the tripping latch and should be avoided. Also, some extra pressure against the tripping latch may be caused by the electro­ magnetic forces due to flow of heavy short-circuit currents through the breaker.
    Lubrication of the bearing surfaces of the operating mechanism should be made as recommended in the manufacturer’s instruction book, but excessive lubrication should be avoided as oily surfaces collect dust and grit and get stiff in cold weather, resulting in excessive friction.
  2. Check oil dielectric strength and color for oil breakers. The dielectric strength must be maintained to pre vent internal breakdown under voltage surges and to enable the interrupter to function properly since its action depends upon changing the internal arc path from a fair conductor to a good insulator in the short interval while the current is passing through zero. Manufacturer’s instructions state the lowest allowable dielectric strength for the various circuit break­ ers. It is advisable to maintain the dielectric strength above 20 kV even though some manufacturer’s instructions allow 16 kV.
    If the oil is carbonized, filtering may remove the suspended particles, but the interrupters, bushings, etc., must be wiped clean. If the dielectric strength is lowered by moisture, an inspection of the fiber and wood parts is advisable and the source of the moisture should be corrected. For these reasons, it is rarely worthwhile to filter the oil in a circuit breaker while it is in service.
  3. Observe breaker operation under load.
  4. Operate breaker manually and electrically and observe for malfunc­ tion. The presence of excessive friction in the tripping mechanism and the margin of safety in the tripping function should be determined by making a test of the minimum voltage required to trip the breaker. This can be accomplished by connecting a switch and rheostat in series in the trip-coil circuit at the breaker (across the terminals to the remote control switch) and a voltmeter across the trip coil. Staring with not over 50 percent of rated trip-coil voltage, gradually in­ crease the voltage until the trip-coil plunger picks up and successfully trips the breaker and record the mini­ mum tripping voltage. Most breakers should trip at about 56 percent of rated trip-coil voltage.
    The trip-coil re­ sistance should be measured and compared with the factor test value to disclose shorted turns.
    Most modern breakers have trip coils which will overheat or burn out if left energized for more than a short pe­ riod. An auxiliary switch is used in series with the coil to open the circuit as soon as the breaker has closed. The auxiliary switch must be properly adjusted and successfully break the arc without damage to the contacts.
    Tests should also be made to deter­ mine the minimum voltage which will close the breaker and the closing coil resistance.
  5. Trip breaker from protective relays.
  6. Check operating mechanism adjustments. Measurements of the mechanical clearances of the operat­ing mechanism associated with the tank or pole should be made. Appre­ ciable variation between the value found and the setting when erected or after the last maintenance overhaul is erected or after the last maintenance overhaul is usually an indication of mechanical trouble. Temperature and difference of temperature between different parts of the mechanism effect the clearances some. The manufacturers’ recommended tolerances usually allow for these effects.
  7. Doble test bushings and breaker.
  8. Measure contact resistance. As long as no foreign material is present, the contact resistance of high-pres- sure, butt-type contacts is practically independent of surface condition. Nevertheless, measurement of the electrical resistance between external bushing terminals of each pole may be regarded as the final “proof of the pudding.” Any abnormal increase in the resistance of this circuit may be an indication of foreign material in contacts, contact loose in support, loose jumper, or loose bushing connection. Any one of these may cause localized heating and deterioration.
    The amount of heat above normal may be readily calculated from the increase in resistance and the current.Resistance of the main contact cir­ cuits can be most conveniently measured with a portable double bridge (Kelvin) or a “Ducter.” The breaker contacts should not be opened during this test because of possible damage to the test equip­ment.
    Table 1
    gives maximum contact resistances for typical classes of breakers.
    .Table 1 | Maximum contact resistances for typical classes of breakers
  9. Make time-travel or motion-analyzer records. Circuit breaker motion an­ alyzers are portable devices designed to monitor the operation of power circuit breakers which permit mechanical coupling of the motion an­ alyzer to the circuit breaker operating rod. These include high-voltage and extra- high-voltage dead tank and SF6 breakers and low-voltage air and vac­ uum circuit breakers.
    Motion analyzers can provide graphic records of close or open initiation signals, contact closing or opening time with respect to initiation signals, contact movement and velocity, and contact bounce or rebound. The records obtained not only indicated when mechanical difficulties are present but also help isolate the cause of the difficulties. It is preferable to obtain a motion-analyzer record on a breaker when it is first installed. This will provide a master record which can be filed and used for comparison with future maintenance checks.
    Tripping and closing voltages should be re­ corded on the master record so subsequent tests can be performed under comparable conditions. Time-travel records are taken on the pole nearest the operating mecha­ nism to avoid the inconsistencies due to linkage vibration and slack in the remote phases..

Internal Inpection Guide – Lines

An internal inspection should include all items listed for an external inspection, plus the breaker tanks or contact heads should be opened and the contacts nd interrupting parts should be inspected. These guidelines are not intended to be a complete list of breaker maintenance but are intended to provide an idea of the scope of each inspection.
A specific checklist should be developed in the field for each type of inspection for each circuit breaker maintained.

Typical Internal Breaker Problems

The following difficulties should be looked for during internal breaker inspections:

  • Tendency for keys, bolts (espe- cially fiber), cotter pins, etc, to come loose.
  • Tendency for wood operating rods, supports, or guides to come loose from clamps or mountings.
  • Tendency for carbon or sludge to form and accumulate in interrupter or on bushings.
  • Tendency for interrupter to flash over and rupture static shield or resis­ tor.
  • Tendency for interrupter parts or barriers to burn or erode.
  • Tendency for bushing gaskets to leak moisture into breaker insulating material.

Fortunately, these difficulties are most likely to appear early in the use of a breaker and would be disclosed by the early internal inspections. As unsatis­ factory internal conditions are corrected and after one or two inspections show the internal conditions to be satisfactory, the frequency of internal inspections may safely be decreased.

Influence Of Duty Imposed


Influence of light duty

Internal inspection of a circuit breaker which has had no interruption duty or switching since the previous inspection will not be particularly beneficial although it will not be a total loss. If the breaker has been energized, but open, erosion in the form or irregular grooves (called tracking) on the inner surface of the interrupter or shields may appear due to electrostatic charging current. This is usually aggravated by a deposit of carbon sludge which has previously been generated by some interrupting operation.
If the breaker has remained closed and carrying current, evidence of heating of the contacts may be found if the contact surfaces were not clean, have oxidized, or if the contact pressure was improper. Any shrinkage and loosening of wood or fiber parts (due to loss of absorbed moisture into the dry oil) will take place following erection, whether the breaker is operated or not. Mechanical operation, however, will make any loosening more evident. It is worthwhile to deliberately impose several switching operations on the breaker before inspection if possible. If this is impossible, some additional information may be gained by operating the breaker several times after it is deenergized, measuring the contact resistance of each pole initially and after each operation.

Influence of normal duty

The relative severity of duty imposed by load switching, line dropping, and fault interruptions depends upon the type of circuit breaker involved. In circuit breakers which employ an oil blast generated by the power arc, the interruption of light faults or the interruption of line charging current may cause more deterioration than the interruption of heavy faults within the rating of the breaker because of low oil pressure. In some designs using this basic principle of interruption, distress at light interrupting duty is minimized by multiple breaks, rapid contact travel, and turbulence of the oil caused by movement of the contact and mech­ anism.

In designs employing a mechanically driven piston to supple­ ment the arc-driven oil blast, the performance is more uniform. Still more uniform performance is usually yielded by designs which depend for arc interruption upon an oil blast driven by mechanical means. In the latter types, erosion of the contacts may appear only with heavy interruptions. The mechanical stresses which accompany heavy interruptions are always more severe.

These variations of characteristic performance among various designs must be considered when judging the need for maintenance from the service records and when judging the performance of a breaker from evidence on inspection. Because of these variations, the practice of evaluating each fault interruption as equivalent to 100 no-load operations, employed by some companies, is necessarily very approximate although it may be a useful guide in the absence of any other information.

Influence of severe duty

Erosion of the contacts and damage from severe mechanical stresses may occur during large fault interruption. The most reliable indication of the stress to which a circuit breaker is subjected during fault interruptions is afforded by automatic oscillograph records. Deterioration of the circuit breaker may be assumed to be proportional to the energy dissipated in the breaker during the interruption.

The energy dissipated is approximately proportional to the current and the duration of arcing; that is, the time from parting of the contacts to interruption of the current. However, the parting of contacts is not always evident on the oscillograms, and it is sometimes necessary to determine this from indicated relay time and the known time for breaker contacts to part. Where automatic oscillograph records are available, they may be as useful in guiding oil circuit breaker maintenance as in showing relay and system performance.

Where automatic oscillographs are not available, a very approximate, but nevertheless useful, indication of fault duty imposed on the circuit breakers may be obtained from relay operation targets and accompanying system conditions. All such data should be tabulated in the circuit breaker maintenance file.



Related articles

Maintenance Of Meduim Voltage Circuit Breakers

Maintenance Of Meduim Voltage Circuit Breakers

Medium-voltage circuit breakers rated between 1 and 72 kV may be assembled into metal-enclosed switchgear line ups for indoor use, or may be individual components installed outdoors in a substation. Air-break circuit breakers replaced oil-filled units for indoor applications, but are now themselves being replaced by vacuum circuit breakers (up to about 35 kV).

Medium voltage circuit breakers which operate in the range of 600 to 15,000 volts should be inspected and maintained annually or after every 2,000 operations, whichever comes first.

The above maintenance schedule is recommended by the applicable standards to achieve required performance from the breakers.

Safety Practices

Maintenance procedures include the safety practices indicated in the ROMSS (Reclamation Operation & Maintenance Safety Standards) and following points that require special attention.

  • Be sure the circuit breaker and its mechanism are disconnected from all electric power, both high voltage and control voltage, before it is inspected or repaired.
  • Exhaust the pressure from air receiver of any compressed air circuit breaker before it is inspected or re­paired.
  • After the circuit breaker has been disconnected from the electrical power, attach the grounding leads properly before touching any of the circuit breaker parts.
  • Do no lay tools down on the equipment while working on it as they may be forgotten when the equipment is placed back in service.

Maintenance Procedures For Medium Voltage Air Circuit Breakers

The following suggestions are for use in conjunction with manufacturer’s instruction books for the maintenance of medium voltage air circuit breakers:

  1. Clean the insulating parts including the bushings.
  2. Check the alignment and condition of movable and stationary contacts and adjust them per the manufacturer’s data.
  3. See that bolts, nuts, washers, cotter pins, and all terminal connections are in place and tight.
  4. Check arc chutes for damage and replace damaged parts.
  5. Clean and lubricate the operating mechanism and adjust it as described in the instruction book. If the operat­ing mechanism cannot be brought into specified tolerances, it will usually indicate excessive wear and the need for a complete overhaul.
  6. Check, after servicing, circuit breaker to verify that contacts move to the fully opened and fully closed positions, that there is an absence of friction or binding, and that electrical operation is functional.

Maintenance Procedures For Medium Voltage Oil Circuit Breakers

The following suggestions are for use in conjunction with the manufacturer’s instruction books for the maintenance of medium-voltage oil circuit breakers:

  1. Check the condition, alignment, and adjustment of the contacts.
  2. Thoroughly clean the tank and other parts which have been in con­ tact with the oil.
  3. Test the dielectric strength of the oil and filter or replace the oil if the dielectric strength is less than 22 kV. The oil should be filtered or replaced whenever a visual inspection shows an excessive amount of carbon, even if the dielectric strength is satisfactory.
  4. Check breaker and operating mechanisms for loose hardware and missing or broken cotter pins, retain­ ing rings, etc.
  5. Adjust breaker as indicated in instruction book.
  6. Clean and lubricate operating mechanism.
  7. Before replacing the tank, check to see there is no friction or binding that would hinder the breaker’s operation. Also check the electrical operation. Avoid operating the breaker any more than necessary without oil in the tank as it is designed to operate in oil and mechanical damage can result from excessive operation without it.
  8. When replacing the tank and refilling it with oil, be sure the gaskets are undamaged and all nuts and valves are tightened properly to prevent leak­ age.

Maintenance Procedures For Medium Voltage Vacuum Circuit Breakers

Direct inspection of the primary contacts is not possible as they are enclosed in vacuum containers. The operating mechanisms are similar to the breakers discussed earlier and may be maintained in the same manner. The following two maintenance checks are suggested for the primary contacts:

  1. Measuring the change in external shaft position after a period of use can indicate extent of contact erosion. Consult the manufacturer’s instruction book.
  2. Condition of the vacuum can be checked by a hipot test. Consult the manufacturer’s instruction book.



Related articles

Maintenance Of Low Voltage Circuit Breakers

Maintenance Of Low Voltage Circuit Breakers

The deterioration of low voltage circuit breaker is normal and  this process begins as soon as the circuit breaker is installed. If  deterioration is not checked, it can cause failures and malfunctions. The purpose of an electrical preventive maintenance and testing program should be to recognize these factors and provide means for correcting them.

A good organized maintenance program can minimize accidents, reduce unplanned shutdowns and lenghten the mean time between failures of electrical equipment.

Benefits of good electrical equipment maintenance can be reduced cost of process shutdown (caused by circuit breaker failure), reduced cost of repairs, reduced downtime of equipment, improved safety of personnel and property.

Frequency Of Maintenance

Low-voltage circuit breakers operating at 600 volts alternating current and below should be inspected and maintained very 1 to 3 years, depending on their service and operating conditions. Conditions that make frequency maintenance and inspection necessary are:

  1. High humidity and high ambient temperature.
  2. Dusty or dirty atmosphere.
  3. Corrosive atmosphere.
  4. Frequent switching operations.
  5. Frequent fault operations.
  6. Older equipment.

A breaker should be inspected and maintained if necessary whenever it has interrupted current at or near its rated capacity.

Maintenance Procedures

Manufacturer’s instructions for each cir­ cuit breaker should be carefully read and followed. The following are general pro­ cedures that should be followed in the maintenance of low-voltage air circuit breakers:

  1. An initial check of the breaker should be made in the TEST position prior to withdrawing it from to enclo­sure.
  2. Insulating parts, including bushings, should be wiped clean of dust and smoke.
  3. The alignment and condition of the movable and stationary contacts should be checked and adjusted ac­cording to the manufacturer’s instruction book.
  4. Check arc chutes and replaces any damaged parts.
  5. Inspect breaker operating mechanism for loose hardware and missing or broken cotter pins, etc. Examine cam, latch, and roller surfaces for damage or wear.
  6. Clean and relubricate operating mechanism with a light machine oil (SAE-20 or 30) for pins and bearings and with a nonhardening grease for the wearing surfaces of cams, rollers, etc.
  7. Set breaker operating mechanism adjustments as described in the manufacturer’s instruction book. If these adjustments cannot be made within the specified tolerances, it may indicate excessive wear and the need for a complete overhaul.
  8. Replace contacts if badly worn or burned and check control device for freedom of operation.
  9. Inspect wiring connections for tightness.
  10. Check after servicing circuit breaker to verify the contacts move to the fully opened and fully closed positions, that there is an absence of friction or binding, and that electrical operation is functional.

Much of the essence of effective electrical equipment preventive maintenance can be sumarrized by four rules:

  • Keep it DRY
  • Keep it CLEAN
  • Keep it COOL
  • Keep it TIGHT




Related articles

Maintenance Of Molded Case Circuit Breakers (MCCB)

Maintenance Of Molded Case Circuit Breakers (MCCB)

The maintenance of circuit breakers deserves special consideration because of their importance for routine switching and for protection of other equipment.

Electric transmission system breakups and equip­ment destruction can occur if a circuit breaker fails to operate because of a lack of preventive maintenance.

The need for maintenance of circuit breakers is often not obvious as circuit breakers may remain idle, either open or closed, for long periods of time. Breakers that remain idle for 6 months or more should be made to open and close several times in succession to verify proper operation and remove any accumulation of dust or foreign material on moving parts and contacts.

Frequency Of Maintenance

Molded case circuit breakers are designed to require little or no routine maintenance throughout their normal life­ time. Therefore, the need for preventive maintenance will vary depending on operating conditions. As an accumulation of dust on the latch surfaces may affect the operation of the breaker, molded case circuit breakers should be exercised at least once per year.

Routine trip testing should be performed every 3 to 5 years.

Routine Maintenance Tests

Routine maintenance tests enable personnel to determine if breakers are able to perform their basic circuit protective functions. The following tests may be performed during routine maintenance and are aimed at assuring that the breakers are functionally operable. The following tests are to be made only on breakers and equipment that are deenergized.

Insulation Resistance Test

A megohmmeter may be used to make tests between phases of opposite polarity and from current-carrying parts of the circuit breaker to ground. A test should also be made between the line and load terminals with the breaker in the open position. Load and line conductors should be dis­ connected from the breaker under insulation resistance tests to prevent test mesurements from also showing resistance of the attached circuit.

Resistance values below 1 megohm are considered unsafe and the breaker should be inspected for pos­ sible contamination on its surfaces.

Milivolt Drop Test

A millivolt drop test can disclose several abnor­ mal conditions inside a breaker such as eroded contacts, contaminated contacts, or loose internal connec­ tions. The millivolt drop test should be made at a nominal direct-current volt­ age at 50 amperes or 100 amperes for large breakers, and at or below rating for smaller breakers. The millivolt drop is compared against manufacturer’s data for the breaker being tested.

Connections Test

The connections to the circuit breaker should be inspected to determine that a good joint is present and that overheating is not occurring. If overheating is indi­ cated by discoloration or signs of arcing, the connections should be re­ moved and the connecting surfaces cleaned.

Overload tripping test

The proper action of the overload tripping components of the circuit breaker can be verified by applying 300 percent of the breaker rated continuous current to each pole. The significant part of this test is the automatic opening of the circuit breaker and not tripping times as these can be greatly affected by ambient conditions and test condi­ tions.

Mechanical operation

The mechanical operation of the breaker should be checked by turning the breaker on and off several times.



Related articles

Air Insulated Substations

Air Insulated Substations

Various factors affect the reliability of a substation, one of which is the arrangement of the switching devices. Arrangement of the switching devices will impact maintenance, protection, initial substation development, and cost. There are six types of substation bus switching arrangements commonly used in air insulated substations:
1. Single bus
2. Double bus, double breaker
3. Main and transfer (inspection) bus
4. Double bus, single breaker
5. Ring bus
6. Breaker and a half

1. Single Bus Configuration

Single Bus Configuration

Single Bus Configuration

This arrangement involves one main bus with all circuits connected directly to the bus. The reliability of this type of an arrangement is very low. When properly protected by relaying, a single failure to the main bus or any circuit section between its circuit breaker and the main bus will cause an outage of the entire system. In addition, maintenance of devices on this system requires the de-energizing of the line connected to the device. Maintenance of the bus would require the outage of the total system, use of standby generation, or switching to adjacent station, if available. Since the single bus arrangement is low in reliability, it is not recommended for heavily loaded substations or substations having a high availability requirement. Reliability of this arrangement can be improved by the addition of a bus tiebreaker to minimize the effect of a main bus failure.

2. Double Bus, Double Breaker Configuration

Double bus, double breaker

Double bus, double breaker

This scheme provides a very high level of reliability by having two separate breakers available to each circuit. In addition, with two separate buses, failure of a single bus will not impact either line. Maintenance of a bus or a circuit breaker in this arrangement can be accomplished without interrupting either of the circuits. This arrangement allows various operating options as additional lines are added to the arrangement; loading on the system can be shifted by connecting lines to only one bus. A double bus, double breaker scheme is a high-cost arrangement, since each line has two breakers and requires a larger area for the substation to accommodate the additional equipment. This is especially true in a low profile configuration. The protection scheme is also more involved than a single bus scheme.

3. Main and Transfer Bus Configuration

Main and transfer bus configuration

Main and transfer bus configuration

This scheme is arranged with all circuits connected between a main (operating) bus and a transfer bus (also referred to as an inspection bus). Some arrangements include a bus tie breaker that is connected between both buses with no circuits connected to it. Since all circuits are connected to the single, main bus, reliability of this system is not very high. However, with the transfer bus available during maintenance, de-energizing of the circuit can be avoided. Some systems are operated with the transfer bus normally de-energized. When maintenance work is necessary, the transfer bus is energized by either closing the tie breaker, or when a tie breaker is not installed, closing the switches connected to the transfer bus. With these switches closed, the breaker to be maintained can be opened along with its isolation switches. Then the breaker is taken out of service. The circuit breaker remaining in service will now be connected to both circuits through the transfer bus. This way, both circuits remain energized during maintenance. Since each circuit may have a different circuit configuration, special relay settings may be used when operating in this abnormal arrangement.

When a bus tie breaker is present, the bus tie breaker is the breaker used to replace the breaker being maintained, and the other breaker is not connected to the transfer bus. A shortcoming of this scheme is that if the main bus is taken out of service, even though the circuits can remain energized through the transfer bus and its associated switches, there would be no relay protection for the circuits. Depending on the system arrangement, this concern can be minimized through the use of circuit protection devices (reclosure or fuses) on the lines outside the substation.
This arrangement is slightly more expensive than the single bus arrangement, but does provide more flexibility during maintenance. Protection of this scheme is similar to that of the single bus arrangement. The area required for a low profile substation with a main and transfer bus scheme is also greater than that of the single bus, due to the additional switches and bus.

4. Double Bus, Single Breaker Configuration

Double bus, single breaker configuration

Double bus, single breaker configuration

This scheme has two main buses connected to each line circuit breaker and a bus tie breaker. Utilizing the bus tie breaker in the closed position allows the transfer of line circuits from bus to bus by means of the switches. This arrangement allows the operation of the circuits from either bus. In this arrangement, a failure on one bus will not affect the other bus. However, a bus tie breaker failure will cause the outage of the entire system. Operating the bus tie breaker in the normally open position defeats the advantages of the two main buses. It arranges the system into two single bus systems, which as described previously, has very low reliability. Relay protection for this scheme can be complex, depending on the system requirements, flexibility, and needs. With two buses and a bus tie available, there is some ease in doing maintenance, but maintenance on line breakers and switches would still require outside the substation switching to avoid outages.

5. Ring Bus Configuration

Ring bus configuration

Ring bus configuration

In this scheme, as indicated by the name, all breakers are arranged in a ring with circuits tapped between breakers. For a failure on a circuit, the two adjacent breakers will trip without affecting the rest of the system. Similarly, a single bus failure will only affect the adjacent breakers and allow the rest of the system to remain energized. However, a breaker failure or breakers that fail to trip will require adjacent breakers to be tripped to isolate the fault. Maintenance on a circuit breaker in this scheme can be accomplished without interrupting any circuit, including the two circuits adjacent to the breaker being maintained. The breaker to be maintained is taken out of service by tripping the breaker, then opening its isolation switches. Since the other breakers adjacent to the breaker being maintained are in service, they will continue to supply the circuits. In order to gain the highest reliability with a ring bus scheme, load and source circuits should be alternated when connecting to the scheme. Arranging the scheme in this manner will minimize the potential for the loss of the supply to the ring bus due to a breaker failure. Relaying is more complex in this scheme than some previously identified. Since there is only one bus in this scheme, the area required to develop this scheme is less than some of the previously discussed schemes. However, expansion of a ring bus is limited, due to the practical arrangement of circuits.

6. Breaker-and-a-Half Configuration

Breaker and a half configuration

Breaker and a half configuration

The breaker-and-a-half scheme can be developed from a ring bus arrangement as the number of circuits increases. In this scheme, each circuit is between two circuit breakers, and there are two main buses. The failure of a circuit will trip the two adjacent breakers and not interrupt any other circuit. With the three breaker arrangement for each bay, a center breaker failure will cause the loss of the two adjacent circuits. However, a breaker failure of the breaker adjacent to the bus will only interrupt one circuit.

Maintenance of a breaker on this scheme can be performed without an outage to any circuit. Further- more, either bus can be taken out of service with no interruption to the service. This is one of the most reliable arrangements, and it can continue to be expanded as required. Relaying is more involved than some schemes previously discussed. This scheme will require more area and is costly due to the additional components.

Table of configurations
ConfigurationReliabilityCostAvailable area
.Single busLeast reliable — single failure can cause complete outageLeast cost — fewer componentsLeast area — fewer components
.Double busHighly reliable — duplicated components; single failure normally isolates single componentHigh cost — duplicated componentsGreater area — twice as many components
.Main bus and .transferLeast reliable — same as
Single bus, but flexibility in operating and maintenance with transfer bus
Moderate cost — fewer componentsLow area requirement —  fewer components
.Double bus, .single breakerModerately reliable — depends on arrangement of components and busModerate cost — more componentsModerate area — more components
.Ring busHigh reliability — single failure isolates single componentModerate cost — more componentsModerate area — increases with number of circuits
.Breaker and a.halfHighly reliable — single circuit failure isolates single circuit, bus failures do not affect circuitsModerate cost — breaker-and-a-half for each circuitGreater area — more components per circuit


Related articles

Compact NSX – prekidač nove generacije

Compact NSX 100A–630A | prekidač nove generacije

Stari Compact NS (100A-630A) definitivno odlazi u penziju, pošto je dugo bio prisutan na tržištu kao jedan od najpouzdanijih prekidača. Zameniće ga mlađi brat Compact NSX, moderan prekidač sa daleko više funkcija i mogućnosti, koji dugo neće imati konkurenciju na polju prekidača do 630A sa mogućnostima kao što su mikroprocesorska zaštita, komunikacija, vizuelni displej, daljinski monitoring energije i snage itd. Budući da je konkurencija na polju izuzetno jaka (ABB, Siemens…), Schneider Electric nije gubio vreme i razvio je ovaj prekidač nove generacije. Budući da cena skoro uvek igra presudnu ulogu kod odlučivanja Investitora ili Panel Builder-a koji tip prekidača koji će se naći u razvodnom ormanu – cena Compact NSX prekidača je čak i niža od starog Compact NS. Odnos cena/kvalitet je kod NSX-a značajno veći nego kod starog NS-a.

Nova mogućnost praćenja potrošnje električne energije kod malih potrošača pojedinačno, pruža detaljnu analizu energetske efikasnosti, kao i mogućnost velike uštede i energije i finansijskih sredstava.

Karakteristike prekidača Compact NSX

  • Nazivna struja: 16 do 630 A
  • 6 nivoa prekidnih moći 25 do 150 kA na 415 V (pogledaj detaljnije)
  • Nazivni napon: do 690 V
  • 2 veličine kućišta za ceo opseg 16 do 630 A
  • Verzija sa 3 i 4 pola
  • Fiksna i izvlačiva izvedba
  • Rastavljanje sa pozitivnom indikacijom prekida
  • Širok opseg zaštitnih jedinica: termomagnetna, elektronska, mikroprocesorska zaštita
  • Diferencijalna zaštita pomoću dodatnih Vigi modula
  • Merenje osnovnih električnih parametara: I, U, P, E, THD, f, CosF
  • Širok opseg pomoćnog pribora i dodataka koji se mogu ugrađivati na samom mestu ugradnje
  • Plug and Play sistem ožičenja komunikacije kao i opseg dodatnih opcija (eksterni displej, modul za održavanje…)
  • Usaglašenost sa medjunarodnim standardima: IEC 60947-1 i 2, Nema, IEC 68230 za klasu tropikalizacije 2
  • Usklađenost za najzahtevnijim specifikacijama kompanija za klasifikaciju u brodogradnji:Bureau Veritas, Lloyd’s Register of Shipping, Det Norske Veritas, RINA.

Kompaktni dizajn i vrlo jednostavna ugradnja mikroprocesorske jedinice MICROLOGIC.
(zarotiraj da vidiš!)

Primena prekidača Compact NSX:

  • Standardne aplikacije sa standardnim strujama kratkog spoja: zgradarstvo, industrijske zgrade i postrojenja, bolnice…
  • Primene koje zahtevaju visoke prekidne moći: procesna industrija, metalurgija
  • Posebno zahtevne aplikacije: brodogradnja
  • Specifične aplikacije: agresivne sredine, 400Hz, 16 2/3 Hz
  • Aplikacije kod kojih je obavezno merenje potrošnje električne energije svakog potrošača


Eksterni displej FDM121 | Micrologic | Komunikacija

Eksterni displej FDM121 | Komunikacija

Kroz direktan pristup detaljnim informacijama, kao i umrežavanjem preko otvorenog protokola (Modbus), Compact NSX omogućava operaterima da optimizuju upravljanje svojim električnim instalacijama i sistemima. Compact NSX može da meri I, U, P, E, THD, f, CosF, zatim procesuira određene akcije, kao i da prikazuje važne podatke na više načina (na direktno ugrađenom ekranu, prednjem panelu ćelije razvodnog ormana sa FDM121, ili daljinski preko POWERLOGIC monitoring sistema – Scada sistema). Compact NSX ima specifične module za kontrolu motora koji omogućuju zaštitu od struje kratkog spoja, preopterećenja, faznog disbalansa i gubitka struje. U kombinaciji sa kontaktorom Schneider Electric-a, prekidač Compact NSX ispunjava sve uslove tipa 2 koordinacije (type 2 coordination) snage do 315kW na 415V prema IEC standardu 60947-4-1. Jedinice za okidanje (trip units) u Compact NSX-u su opremljene sa moment-limitiranim šrafovima i MITOP integrisanim uređajem za okidanje, koji dozvoljavaju da budu ugrađene tačno na svoje mesto u prekidaču. Jednom kada se nameste, električno testiranje više nije potrebno. Pre-ožičeni komunikacioni kablovi i “plug-and-play” interfejs omogućavaju jednostavnu i laku integraciju sa komunikacionim mrežama.

Korisnici mogu da prilagođavaju alarm za sve parametre , biraju prioritete koji će biti prikazani na displeju MICROLOGIC-a ili FDM121, kao i podešavaju vreme režima odlaganja akcije. Konstantno aktiviran zapis log-ova od svih događaja na prekidaču (log events) pružaju korisne informacije instalaterima nakon događaja (kratkog spoja, iznenadnog isključenja…).

Dodatna oprema za fiksni prekidač Compact NSX
(stani mišem da vidiš!)

Korisni linkovi sa dokumentacijom za Compact NSX:


Related articles

What to use? Vacuum or SF6 circuit breaker?

What CB to use? Vacuum or SF6 circuit breaker?

Until recently oil circuit breakers were used in large numbers for Medium voltage Distribution system in many medium voltage switchgears. There are number of disadvantages of using oil as quenching media in circuit breakers. Flammability and high maintenance cost are two such disadvantages! Manufacturers and Users were forced to search for different medium of quenching. Air blast and Magnetic air circuit breakers were developed but could not sustain in the market due to other disadvantages associated with such circuit breakers. These new types of breakers are bulky and cumbersome. Further research were done and simultaneously two types of breakers were developed with SF6 as quenching media in one type and Vacuum as quenching media in the other. These two new types of breakgasers will ultimately replace the other previous types completely shortly. There are a few disadvantages in this type of breakers also. One major problem is that the user of the breakers are biased in favour of old fashioned oil circuit breakers and many of the users always have a step motherly attitude to the new generations of the breakers. However in due course of time this attitude will disappear and the new  type of breakers will get its acceptance among the users and ultimately they will completely replace the oil circuit breakers. An attempt is made to make a comparison between the SF6 type and vacuum type circuit breakers with a view to find out as to which of the two types is superior to the other. We will now study in detail each type separately before we compare them directly.

Vacuum Circuit Breaker
Evolis Circuit Breaker

Evolis MV Circuit Breaker

In a Vacuum circuit breaker, vacuum interrupters are used for breaking and making load and fault currents. When the contacts in vacuum interrupter separate, the current to be interrupted  initiates a metal vapour arc discharge and flows through the plasma until the next current zero. The arc is then extinguished and the conductive metal vapour condenses on the metal surfaces within a matter of micro seconds. As a result the dielectric strength in the breaker builds up very rapidly.

The properties of a vacuum interrupter depend largely on the material and form of the contacts. Over the period of their development, various types of contact material have been used. At the moment it is accepted that an oxygen free copper chromium alloy is the best material for High voltage circuit breaker. In this alloy , chromium is distributed through copper in the form of fine grains. This material combines good arc extinguishing characteristic with a reduced tendency to contact welding and low chopping current when switching inductive current. The use of this special material is that the current chopping is limited to 4 to 5 Amps.

At current under 10KA, the Vacuum arc burns as a diffuse discharge. At high values of current the arc changes to a constricted form with an anode spot. A  constricted arc that remain on one spot for too long can thermically over stress the contacts to such a degree that the deionization of the contact zone at current zero can no longer be guaranteed . To overcome this problem the arc root must be made to move over the contact surface. In order to achieve this, contacts are so shaped that the current flow through them results in a magnetic field being established which is at right angles to the arc axis. This radial field causes the arc root to rotate rapidly around the contact resulting in a uniform distribution of the heat over its surface. Contacts of this type are called radial magnetic field electrodes and they are used in the majority of circuit breakers for medium voltage application.

A new design has come in Vacuum interrupter, in which switching over the arc from diffusion to constricted state by subjecting the arc to an axial magnetic field. Such a field can be provided by leading the arc current through a coil suitably arranged outside the vacuum chamber. Alternatively the field can be provided by designing the contact to give the required contact path. Such contacts are called axial magnetic field electrodes. This principle has advantages when the short circuit current is in excess of 31.5 KA.

SF6 Gas Circuit Breaker
SF6 circuit breakers

SF6 circuit breakers

In an SF6 circuit-breaker, the current continues to flow after contact separation through the arc whose plasma consists of ionized SF6 gas. For, as long as it is burning, the arc is subjected to a constant flow of gas which extracts heat from it. The arc is extinguished at a current zero, when the heat is extracted by the falling current. The continuing flow of gas finally de-ionises the contact gap and establishes the dielectric strength required to prevent a re-strike.

The direction of the gas flow, i.e., whether it is parallel to or across the axis of the arc, has a decisive influence on the efficiency of the arc interruption process. Research has shown that an axial flow of gas creates a turbulence which causes an intensive and continuous interaction between the gas and the plasma as the current approaches zero. Cross-gas-flow cooling of the arc is generally achieved in practice by making the arc move in the stationary gas. This interruption process can however, lead to arc instability and resulting great fluctuations in the interrupting capability of the circuit breaker.

In order to achieve a flow of gas axially to the arc a pressure differential must be created along the arc. The first generation of the SF6 circuit breakers used the two-pressure principle of the air-blast circuit-breaker. Here a certain quantity of gas was kept stored at a high pressure and released into the arcing chamber. At the moment high pressure gas and the associated compressor was eliminated by the second generation design. Here the pressure differential was created by a piston attached to the moving contacts which compresses the gas in a small cylinder as the contact opens. A disadvantage is that this puffer system requires a relatively powerful operating mechanism.

Neither of the two types of circuit breakers described was able to compete with the oil circuit breakers price wise. A major cost component of the puffer circuit-breaker is the operating mechanism; consequently developments followed which were aimed at reducing or eliminating this additional cost factor. These developments concentrated on employing the arc energy itself to create directly the pressure-differential needed. This research led to the development of the self-pressuring circuit-breaker in which the over – pressure is created by using the arc energy to heat the gas under controlled conditions. During the initial stages of development, an auxiliary piston was included in the interrupting mechanism, in order to ensure the satisfactory breaking of small currents. Subsequent improvements in this technology have eliminated this requirement and in the latest designs the operating mechanism must only provide the energy needed to move the contacts.

Parallel to the development of the self-pressuring design, other work resulted in the rotating – arc SF6 gas circuit breaker. In this design the arc is caused to move through, in effect the stationery gas. The relative movement between the arc and the gas is no longer axial but radial, i.e., it is a cross-flow mechanism. The operating energy required by circuit breakers of this design is also minimal.

Table 1. Characteristics of the SF6 and vacuum current interrupting technologies.

SF6 Circuit BreakersVacuum Circuit Breakers
CriteriaPuffer Circuit BreakerSelf-pressuring circuit-breakerContact material-Chrome-Copper
Operating energy requirementsOperating Energy requirements are high, because the mechanism must supply the energy needed to compress the gas.Operating Energy requirements are low, because the mechanism must move only relatively small masses at moderate speed, over short distances. The mechanism does not have to provide the energy to create the gas flowOperating energy requirements are low, because the mechanism must move only relatively small masses at moderate speed, over very short distances.
Arc EnergyBecause of the high conductivity of the arc in the SF6 gas, the arc energy is low. (arc voltage is between 150 and 200V.)Because of the very low voltage across the metal vapour arc, energy is very low. (Arc voltage is between 50 and 100V.)
Contact ErosionDue to the low energy the contact erosion is small.Due to the very low arc energy, the rapid movement of the arc root over the contact and to the fact that most of the metal vapour re-condenses on the contact, contact erosion is extremely small.
Arc extinguishing mediaThe gaseous medium SF6 possesses excellent dielectric and arc quenching properties. After arc extinction, the dissociated gas molecules recombine almost completely to reform SF6. This means that practically no loss/consumption of the quenching medium occurs. The gas pressure can be very simply and permanently supervised. This function is not needed where the interrupters are sealed for life.No additional extinguishing medium is required. A vacuum at a pressure of 10-7 bar or less is an almost ideal extinguishing medium. The interrupters are ‘sealed for life’ so that supervision of the vacuum is not required.
Switching behavior in relation to current choppingThe pressure build-up and therefore the flow of gas is independent of the value of the current. Large or small currents are cooled with the same intensity. Only small values of high frequency, transient currents, if any, will be interrupted. The de-ionization of the contact gap proceeds very rapidly, due to the electro-negative characteristic of the SF6 gas and the arc products.The pressure build-up and therefore the flow of gas is dependent upon the value of the current to be interrupted. Large currents are cooled intensely, small currents gently. High frequency transient currents will not, in general, be interrupted. The de-ionization of the contact gap proceeds very rapidly due to the electro-negative characteristic of the SF6 gas and the products.No flow of an ‘extinguishing’ medium needed to extinguish the vacuum arc. An extremely rapid de-ionization of the contact gap, ensures the interruption of all currents whether large or small. High frequency transient currents can be interrupted. The value of the chopped current is determined by the type of contact material used. The presence of chrome in the contact alloy with vacuum also.
No. of short-circuit operation10—5010—5030—100
No. full load operation5000—100005000—1000010000—20000
No. of mechanical operation5000—200005000—2000010000—30000

Comparison of the SF6 And Vacuum Technologies

The most important characteristics of the SF6 gas and vacuum-circuit breakers, i.e., of SF6 gas and vacuum as arc-extinguishing media are summarized in Table-1.

In the case of the SF6 circuit-breaker, interrupters which have reached the limiting number of operations can be overhauled and restored to ‘as new’ condition. However, practical experience has shown that under normal service conditions the SF6 interrupter never requires servicing throughout its lifetime. For this reason, some manufacturers no longer provide facilities for the user to overhaul the circuit-breaker, but have adopted a ‘sealed for life’ design as for the vacuum-circuit breaker.

The operating mechanisms of all types of circuit-breakers require servicing, some more frequently than others depending mainly on the amount of energy they have to provide. For the vacuum-circuit breaker the service interval lies between 10,000 and 20,000 operations. For the SF6 designs the value varies between 5,000 and 20,000 whereby, the lower value applies to the puffer circuit-breaker for whose operation, the mechanism must deliver much more energy.

The actual maintenance requirements of the circuit-breaker depend upon its service duty, i.e. on the number of operations over a given period of time and the value of current interrupted. Based on the number of operations given in the previous section, it is obvious that SF6 and vacuum circuit-breakers used in public supply and /or industrial distribution systems will, under normal circumstances, never reach the limits of their summated breaking current value. Therefore, the need for the repair or replacement of an interrupter will be a rare exception and in this sense these circuit-breakers can be considered maintenance-free. Service or maintenance requirements are therefore restricted to routine cleaning of external surfaces and the checking and lubrication of the mechanism, including the trip-linkages and auxiliary switches. In applications which require a very high number of circuit-breaker operations e.g. for arc furnace duty or frequently over the SF6 design, due to its higher summated-breaking current capability. In such cases it is to be recommended that the estimation of circuit-breaker maintenance costs be given some consideration and that these be included in the evaluation along with the initial, capital costs.


In practice, an aspect of the utmost importance in the choice of a circuit-breaker is reliability.

The reliability of a piece of equipment is defined by its mean time to failure (MTF), i.e. the average interval of time between failures. Today, the SF6 and vacuum circuit-breakers made use of the same operating mechanisms, so in this regard they can be considered identical.

However, in relation to their interrupters the two circuit breakers exhibit a marked difference. The number of moving parts is higher for the SF6 circuit-breaker than that for the vacuum unit. However, a reliability comparison of the two technologies on the basis of an analysis of the number of components are completely different in regards design, material and function due to the different media. Reliability is dependent upon far too many factors, amongst others, dimensioning, design, base material, manufacturing methods, testing and quality control procedures, that it can be so simply analyzed.

In the meantime, sufficient service experience is available for both types of circuit-breakers to allow a valid practical comparison to be made. A review of the available data on failure rates confirms that there is no discernible difference in reliability between the two circuit-breaker types. More over, the data shows that both technologies exhibit a very high degree of reliability under normal and abnormal conditions.

Switching of fault currents

Today, all circuit-breakers from reputable manufacturers are designed and type-tested in conformance with recognized national or international standards (IEC56). This provides the assurance that these circuit-breakers will reliably interrupt all fault currents up to their maximum rating. Further, both types of circuit-breakers are basically capable of interrupting currents with high DC components; such currents can arise when short circuits occur close to a generator. Corresponding tests have indeed shown that individual circuit-breakers of both types are in fact, capable of interrupting fault currents with missing current zeros i.e. having a DC component greater than 100 per cent. Where such application is envisaged, it is always to be recommended that the manufacturer be contacted and given the information needed for a professional opinion.

As regards the recovery voltage which appears after the interruption of a fault current the vacuum-circuit breaker can, in general, handle voltages with RRV values of up to 5KV. SF6 circuit-breakers are more limited, the values being in the range from 1 to 2 KV. In individual applications, e.g. in installations with current limiting chokes or reactors, etc., With SF6 circuit-breakers it may be advisable or necessary to take steps to reduce that rate of rise of the transient recovery voltage.

Switching small inductive currents

The term, small inductive currents is here defined as those small values of almost pure inductive currents, such as occur with unloaded transformers, motor during the starting phase or running unloaded and reactor coils. When considering the behavior of a circuit-breaker interrupting such currents, it is necessary to distinguish between high frequency and medium frequency transient phenomena.

Medium frequency transients arise from, amongst other causes, the interruption of a current before it reaches its natural zero. All circuit-breakers can, when switching currents of the order of a few hundred amperes and, due to instability in the arc, chop the current immediately prior to a current zero.

This phenomenon is termed real current chopping. When it occurs, the energy stored in the load side inductances oscillates through the system line to earth capacitances (winding and cable capacitances) and causes an increase in the voltage. This amplitude of the resulting over voltage is a function of the value of the current chopped. The smaller the chopped current, the lower the value of the over voltage.

In addition to the type of circuit – breaker, the system parameters at the point of installation are factors which determine the height of the chopping current, in particular the system capacitance parallel to the circuit breaker is of importance. The chopping current of SF6 circuit-breakers is essentially determined by the type of circuit-breaker. The value of chopping current varies from 0.5A to 15A, whereby the behavior of the self – pressuring circuit-breaker is particularly good, its chopping current being less than 3A.This ‘soft’

Switching feature is attributable to the particular characteristics of the interrupting mechanism of the self-pressuring design and to the properties of the SF6 gas itself.

In the early years of the development of the vacuum circuit-breaker the switching of small inductive currents posed a major problem, largely due to the contact material in use at that time. The introduction of the chrome copper contacts brought a reduction of the chopping current to between 2 to 5A.The possibility of impermissible over voltages arising due to current chopping has been reduced to a negligible level.

High frequency transients arise due to pre- or re-striking of the arc across the open contact gap. If, during an opening operation, the rising voltage across the opening contacts, exceed the dielectric strength of the contact gap , a re-strike occurs. The high-frequency transient current arising from such a re-strike can create high frequency current zeros causing the circuit-breaker to, interrupt again. This process can cause a further rise in voltage and further re-strikes. Such an occurrence is termed as multiple restriking.

With circuit- breakers that can interrupt high frequency transient currents, re-striking can give rise to the phenomenon of virtual current chopping. Such an occurrence is possible when a re-strike in the first-phase-to-clear, induces high frequency transients in the other two phases, which are still carrying service frequency currents. The superimposition of this high frequency oscillation on the load current can cause an apparent current zero and an interruption by the circuit-breaker, although the value of load current may be quite high. This phenomenon is called virtual current chopping and can result in a circuit breaker ‘chopping’ very much higher values of current than it would under normal conditions. The results of virtual current chopping are over-voltages of very high values.

This phenomenon is termed real current chopping. When it occurs, the energy Stored in the load side inductances oscillates through the system line to earth capacitances (winding and cable capacitances) and causes an increase in the voltage. This amplitude of the resulting over voltage is a function of the value of the current chopped. The smaller the chopped current, the lower the value of the over voltage.

In addition to the type of circuit – breaker, the system parameters at the point of installation are factors which determine the height of the chopping current, in particular the system capacitance parallel to the circuit breaker is of importance. The chopping current of SF6 circuit-breakers is essentially determined by the type of circuit-breaker. The value of chopping current varies from 0.5A to 15A, whereby the behaviour of the self – pressuring circuit-breaker is particularly good, its chopping current being less than 3A.This ‘soft’   Switching feature is attributable to the particular characteristics of the interrupting mechanism of the self-pressuring design and to the properties of the SF6 gas itself.

In the early years of the development of the vacuum circuit-breaker the switching of small inductive currents posed a major problem, largely due to the contact material in use at that time. The introduction of the chrome copper contacts brought a reduction of the chopping current to between 2 to 5A.The possibility of impermissible over voltages arising due to current chopping has been reduced to a negligible level.

High frequency transients arise due to pre- or re-striking of the arc across the open contact gap. If, during an opening operation, the rising voltage across the opening contacts exceeds the dielectric strength of the contact gap, a re-strike occurs. The high-frequency transient current arising from such a re-strike can create high frequency current zeros causing the circuit-breaker to, interrupt again. This process can cause a further rise in voltage and further re-strikes. Such an occurrence is termed as multiple re-striking.

With circuit- breakers that can interrupt high frequency transient currents, re-striking can give rise to the phenomenon of virtual current chopping. Such an occurrence is possible when a re-strike in the first-phase-to-clear, induces high frequency transients in the other two phases, which are still carrying service frequency currents. The superimposition of this high frequency oscillation on the load current can cause an apparent current zero and an interruption by the circuit-breaker, although the value of load current may be quite high. This phenomenon is called virtual current chopping and can result in a circuit breaker ‘chopping’ very much higher values of current than it would under normal conditions. The results of virtual current chopping are over-voltages of very high values

Table2. Comparison of the SF6 And Vacuum Technologies In Relation To Operational Aspects

CriteriaSF6 BreakerVacuum Circuit Breaker
Summated current cumulative10-50 times rated short circuit current30-100 times rated short circuit current
Breaking current capacity of interrupter5000-10000 times10000-20000 times
Mechanical operating life5000-20000 C-O operations10000-30000 C-O operations
No operation before maintenance5000-20000 C-O operations10000-30000 C-O operations
Time interval between servicing Mechanism5-10 years5-10 years
Outlay for maintenanceLabour cost High, Material cost LowLabour cost Low, Material cost High
Dielectric withstand strength of the contact gapHighVery high

Very extensive testing has shown that, because of its special characteristics the SF6 self-pressuring circuit-breaker possesses considerable advantages in handling high frequency transient phenomena, in comparison with both the puffer type SF6 and the vacuum circuit breakers. The past few years have seen a thorough investigation of the characteristics of vacuum circuit breakers in relation to phenomena such as multiple re-striking and virtual current chopping. These investigations have shown that the vacuum circuit-breaker can indeed cause more intense re-striking and hence more acute over voltages than other types. However, these arise only in quite special switching duties such as the tripping of motors during starting and even then only with a very low statistical probability. The over-voltages which are created in such cases can be reduced to safe levels by the use of metal oxide surge diverters.

Table3. Comparison of the SF6 And Vacuum Switching Technologies In Relation To Switching Applications

CriteriaSF6 Circuit BreakerVacuum Circuit Breaker
Switching of Short circuit current with High DC componentWell suitedWell suited
Switching of Short circuit current with High RRVWell suited under certain conditions (RRV>1-2 kV per Milli secondsVery well suited
Switching of transformersWell suited.Well suited
Switching of reactorsWell suitedWell suited. Steps to be taken when current <600A. to avoid over voltage due to current chopping
Switching of capacitorsWell suited. Re-strike freeWell suited. Re-strike free
Switching of capacitors back to backSuited. In some cases current limiting reactors required to limit inrush currentSuited. In some cases current limiting reactors required to limit inrush current
Switching of arc furnaceSuitable for limited operationWell suited. Steps to be taken to limit over voltage.


Related articles

Theory and examples of short circuit calculation

Theory and examples of short circuit calculation

An electrical transformer substation consist of a whole set of devices (conductors, measuring and control aparatus and electric machines) dedicated to transforming the voltage supplied by the medium voltage distribution grid (e.g. 12kV or 20kV), into voltage suitable for supplying low voltagelines wit power (400V-690V).


Related articles


What is cascading?

Cascading is the use of the current limiting capacity of circuit breakers at a given point to permit installation of lower-rated and therefore lower-cost circuit breakers downstream. The upstream circuit breakers acts as a barrier against short-circuit currents. In this way, downstream circuit breakers with lower breaking capacities than the prospective short-circuit (at their point of installation) operate under their normal breaking conditions. Since the current is limited throughout the circuit controlled by the limiting circuit breaker, ascading applies to all switchgear downstream. It is not restricted to two consecutive devices.

General use of cascadingcom

With cascading, the devices can be installed in different switchboards. Thus, in general, cascading refers to any combination of circuit breakers where a circuit breaker with a breaking capacity less than the prospective Isc at its point of installation can be used. Of course, the breaking capacity of the upstream circuit breaker must be greater than or equal to the prospective short-circuit current at its point of installation.
The combination of two circuit breakers in cascading configuration is covered by the following standards:

  • IEC 60947-2 (construction)
  • NF C 15-100, § 434.3.1 (installation)
Coordination between circuit breakers

The use of a protective device possessing a breaking capacity less than the prospective short-circuit current at its installation point is permitted as long as another device is installed upstream with at least the necessary breaking capacity. In this case, the characteristics of the two devices must be coordinated in such a way that the energy let through by the upstream device is not more than that which can be withstood by the downstream device and the cables protected by these devices without damage.
Cascading can only be checked by laboratory tests and the possible combinations can be specified only by the circuit breaker manufacturer.

Cascading and protection discrimination

In cascading configurations, due to the Roto-active breaking technique, discrimination is maintained and in some cases, even enhanced.


Related articles